UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 20122013 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR)PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of September 30, 2013,March 31, 2014, OPCo’s net deferred fuel balance was $467$426 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.

 

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which2015.  This ruling was generally upheld in PUCO rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM)RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price, which includes reserve margins, is approximately $33/MW day through May 2014.2014 and $148/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.  As of September 30, 2013, OPCo’s incurred deferred capacity costs balance was $228 million, including debt carrying costs.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR),RSR, effective September 2012.  The RSR will beis being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.  As of March 31, 2014, OPCo’s incurred deferred capacity costs balance was $348 million, including debt carrying costs.

In JuneNovember 2013, intervenors in the PUCO issued an order approving OPCo’s competitive bid process (CBP) docket filed recommendationswith modifications.  The modifications include the delay of the energy auctions that include prospective rate reductionswere originally ordered in the ESP order.  In February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.  The PUCO also approved the unbundling of the FAC into fixed and non-energy FAC issues.  OPCo maintains that the August 2012 ESP order fixed OPCo’s non-energy generation rates through December 31, 2014energy-related components and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015.  However, intervenors maintained that OPCo’s non-energy generation rates should be reduced prior to January 1, 2015an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% priorauctioned.  Additionally, the PUCO ordered that intervenor concerns related to June 2014 and 60% for the period June 1, 2014recovery of the fixed fuel costs through December 31, 2014).  Depending upon actual customer switching levelspotentially both the FAC and the timingapproved capacity charges be addressed in subsequent FAC proceedings.  Management believes that these intervenor concerns are without merit.  In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 – 2013 FAC proceeding to separately examine the recovery of the auctions,fixed fuel costs, including OVEC.  In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC.

In December 2013, OPCo estimatesfiled an application with the PUCO to approve an ESP that these capacity issues could reduce OPCo’s projected future revenues by up to approximately $155 million forincludes proposed rate adjustments and the period January 2014continuation and modification of certain existing riders effective June 2015 through May 2018.  This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.  The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo.  Additionally, the

application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 if adopted byESP in which the PUCO. An additional proposal to prospectively offsetunrecovered portion of the deferred capacity costs based uponwill continue to be collected at the resultsrate of $4.00/MWh until the balance of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adoptedcapacity deferrals has been collected.  Management intends to file this application in lightthe second quarter of prior PUCO orders.  Hearings related to the CBP were held2014.  A hearing at the PUCO in the ESP case is scheduled for June and July 2013.  A decision from the PUCO is pending. 2014.

If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity costs,cost, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 3.4.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service.  The reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-systemwholesale sales, (c) deferral of unrecovered capacity costs, (d) Retail Stability RiderRSR collections and (e) revenues from AEP Energy.  AEP Energy is our CRES provider and part of our Generation and& Marketing segment which targets retail customers, both within and outside of our retail service territory.

Customer Demand

In comparison to 2012,2013, heating degree days in 2014 were up 40% in our western region and 24% in our eastern region.  Our weather-normalized retail sales were down 1.5% and 1.9%volumes for the threefirst quarter of 2014 increased by 1.5% from their levels for the first quarter of 2013.  First quarter 2014 weather-adjusted residential and nine months ended September 30, 2013, respectively.  commercial customer sales were up 4.4% and 2.9%, respectively, from their levels for the first quarter of 2013.  Residential and commercial customer counts grew 0.4% and 0.8% in the first quarter of 2014, respectively, from the first quarter of 2013.

Our industrial sales declined 3.9% and 5.1%, respectively, partiallyvolumes in the first quarter 2014 decreased 2.9% from the first quarter of 2013 due mainly to lower production levels atthe closure of Ormet, a large aluminum company.  Ormet hashad a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced that it iswas unable to emerge from bankruptcy and that it has shut down its operations effective immediately.  Excluding Ormet, our first quarter 2014 industrial sales volumes increased 2.2% over the first quarter of 2013.  The loss of Ormet's load will not have a material impact on future gross margin.  Powermargin because power previously sold to Ormet will be available to be soldfor sale into generally higher priced wholesale markets.

PJM Capacity Market

If corporate separationThrough May 2015, AGR will provide generation capacity to OPCo for both switched and asset transfersnon-switched OPCo generation customers.  AGR is required to offer all of its remaining generation capacity in the PJM RPM auction, which is conducted three years in advance of the actual delivery year.  AGR generation assets are approvedsubject to PJM capacity prices for periods after May 2015.  For switched customers, OPCo pays AGR $188.88/MW day.  For non-switched OPCo generation customers, OPCo pays AGR for capacity.  AGR’s non-OPCo load is subject to the PJM RPM auction.  Shown below are the current auction prices for capacity, as filed, AEPGenCo will be subjectannounced/settled by PJM:

Due to the volatility and uncertainty in prices, we formed a coalition with other utility companies to address mutual concerns related to the PJM capacity auction prices after May 2015process, including: (a) import limits for the majoritypower without firm transmission, (b) placing bidding caps on available demand response resources in comparison to base generation capacity, (c) modification and enforcement of the current OPCo-owned generation assets.  Under the previously approved June 2012 – May 2015 ESP, OPCo is allowedtiming of demand response requirements to receive revenues through May 2015better reflect real-time capacity requirements and (d) tightened rules for the generation assets from base generation rates and allowed to defer incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The PJM base capacity price for the planning year June 2015 through May 2016 was previously announced as $136.00/MW day.  In May 2013, PJM announcedincremental auctions in which speculative bidders currently can sell resources in the base auction and buy back that capacity auction price for the June 2016 through May 2017 planning period would be $59.37/MW day.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant.  In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013.  The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See the “2012 Louisiana Formula Rate Filing” section of Note 3.4.

In March 2014, APCo filed a generation and distribution base rate biennial review with the Virginia SCC.  In accordance with a Virginia statute, APCo did not request an $85 million annual increase in base rates based upon aas its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.2%10.9%.  InThe filing included a March 2013 order,request to decrease generation depreciation rates, effective February 2015, primarily due to the IURC approved an adjustment which increasedchange in the authorized annual increase in base ratesexpected service life of certain plants.  Additionally, the filing included a request to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objectionsamortize $7 million annually for two years, beginning February 2015, related to certain aspectsdeferred costs.  If any of the rate case.  If the order is overturned by the Indiana Court of Appeals,these costs are not recoverable, it could reduce future net income and cash flows.flows and impact financial condition.  See the “2011 Indiana“2014 Virginia Biennial Base Rate Case” section of Note 3.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of September 30, 2013,March 31, 2014, I&M has incurred $285costs of $405 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery of in a subsequent base rate case.  I&M was granted recoverywill recover approved costs through an LCM rider which will be determined by a proceeding in the fourth quarter of 2013 and semi-annual proceedings thereafter.proceedings.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in its rates.  In OctoberDecember 2013, I&M filed an application with the IURC forissued an interim order authorizing the implementation of LCM rider rates to be effective January 2014.2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to certainthe approved projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON.CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.  See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 3.4.

In August 2012, the ordinary coursePUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of business, weMarch 31, 2014, OPCo’s net deferred fuel balance was $426 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are involvedpending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs balance.

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015.  This ruling was generally upheld in employment, commercial, environmentalPUCO rehearing orders in January and regulatory litigation.  Since itMarch 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The OPCo RPM price, which includes reserve margins, is difficultapproximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to predict the outcomerecovery of these proceedings, we cannot predictdeferred capacity costs.  In April and May 2013, OPCo and various intervenors filed appeals with the eventual resolution, timing or amountSupreme Court of any loss, fine or penalty.  We assessOhio challenging portions of the probabilityPUCO’s ESP order, including the RSR.  As of lossMarch 31, 2014, OPCo’s incurred deferred capacity costs balance was $348 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications.  The modifications include the delay of the energy auctions that were originally ordered in the ESP order.  In February 2014, OPCo conducted an energy-only auction for each contingency10% of the SSO load with delivery beginning April 2014 through May 2015.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and accrue a liability for casesthe remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.  The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned.  Additionally, the PUCO ordered that have a probable likelihoodintervenor concerns related to the recovery of loss if the loss can be estimated.  For details on our regulatory proceedings and pending litigation see Note 3 – Rate Matters, Note 5 – Commitments, Guarantees and Contingenciesfixed fuel costs through potentially both the FAC and the “Litigation” section of “Management’s Discussionapproved capacity charges be addressed in subsequent FAC proceedings.  Management believes that these intervenor concerns are without merit.  In January 2014, the PUCO denied all rehearing requests and Analysis of Financial Condition and Results of Operations”agreed to issue a supplemental request for an independent auditor in the 2012 Annual Report.– 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC.  In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC.

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018.  This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.  The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of September 30, 2013,March 31, 2014, SWEPCo has incurred $17$48 million in costs related to these projects.  Management intendsSWEPCo will seek to seek recovery ofrecover these projectsproject costs from SWEPCo’sits state commissions.commissions and FERC customers.

In 2010,March 2014, APCo filed a generation and distribution base rate biennial review with the Federal EPA publishedVirginia SCC.  In accordance with a proposed ruleVirginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%.  The filing included a request to regulatedecrease generation depreciation rates, effective February 2015, primarily due to the disposal and beneficial re-usechange in the expected service life of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The rule containscertain plants.  Additionally, the filing included a request to amortize $7 million annually for two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow statesyears, beginning February 2015, related to retain primary authority to regulate the beneficial re-use and disposalcertain deferred costs.  If any of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.  The Federal EPA has also announced its intention to complete a risk assessment of various beneficial

In April and May 2012, I&M filed a petition with the IURC and the actions we are taking to address potential impacts, see Part IMPSC, respectively, for approval of the 2012 Form 10-K underLCM Project, which consists of a group of capital projects to ensure the headings entitled “Business – General – Environmentalsafe and Other Matters”reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and “Management’s Discussion and Analysis2037 for Unit 2).  The estimated cost of Financial Condition and Resultsthe LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of Operations.”March 31, 2014, I&M has incurred costs of $405 million related to the LCM Project, including AFUDC.

RESULTS OF OPERATIONS

Our primary business is the generation, transmission and distribution of electricity.  Within our Utility OperationsVertically Integrated Utilities segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our reportable segments and their related business activities are outlined below:

Net Income decreasedincreased from $488 million in 2012 to $434$364 million in 2013 to $561 million in 2014 primarily due to:

Our results of operations are discussed below by operating segment.

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

Expenses and Other and Income Tax Expense changed between years as follows:

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity and certain costs of service for retail operations were as follows:

Expenses and Other and Income Tax Expense changed between years as follows: